The present invention relates to a process of stimulating oil recovery from subterranean reservoirs or formations utilizing injection of gases. It is more specifically concerned with improving the efficiency of a secondary oil recovery process wherein foam is generated in situ to reduce permeability of the more permeable zones of a subterranean reservoir during a gas flooding treatment.
Significant quantities of low gravity crude oil exist in underground formations. Because of this, techniques have been developed for stimulating production of oil from such reservoirs. However, the high viscosity of the oil remaining in such formations makes recovery difficult and expensive. A number of methods designed to stimulate recovery of high viscosity petroleum have been used, including water flooding, steam injection, and gas injection, but none to date has been totally satisfactory. Typically, water flooding is inefficient for displacing viscous oil due to the oil's high viscosity. Steam injection lowers viscosity, but is also unsatisfactory in certain types of formations and requires availability of inexpensive fuel and a large supply of clean water. In the most common method of steam injection, "huff and puff" steam injection, the well is used for alternate injection of steam and production of reservoir fluids. A recent variation of the "huff and puff" steam injection method for reducing the viscosity of viscous oil is disclosed by West in U.S. Pat. No. 3,782,470. Immediately following the injection phase of a "huff and puff" steam stimulation process, which lowers viscosity of the oil, a non-condensing, non-oxidizing gas is injected at ambient temperature. The gas displaces the low viscosity oil and thereby improves oil production rates, reduces the volume of steam required, and improves the water-oil ratio of the well. However, where a multi-component gas is employed, such as natural gas, the higher molecular weight hydrocarbons tend to condense as the formation cools following steam injections. The condensed hydrocarbons have high solubility and even miscibility with most crudes. As a result, crude oil may be miscibly displaced from the vicinity of the wellbore, resulting in reduced permeability to oil at the wellbore.
A typical method of gas flooding utilizes recycled reservoir gases, reinjecting at the injection well at least a portion of those gases produced at the production well. Such produced gases often contain small amounts of components which become acidic when dissolved into reservoir waters, such as hydrogen sulfide, sulfur oxides, and carbon dioxide. If present in large amounts, the acidic components in reinjected reservoir gases may cause damage to the area surrounding the wellstem. To avoid these problems it has recently been proposed that nitrogen be used in gas flooding regimes.
To enhance the effectiveness of gas flooding, a miscible gas that reduces viscosity of the oil may be used. However, unless the solvent gas remains soluble, it will usually be produced preferentially to the oils as an immiscible mobile phase. One of the most successful gas solvents used to stimulate recovery of viscous oils is carbon dioxide. The high solution factor of carbon dioxide in crude oil causes the viscosity of the carbon dioxide-crude oil solution to be markedly lower than that of the crude alone. For illustrative examples of stimulation processes utilizing carbon dioxide, reference is made to U.S. Pat. No. 3,442,332, which incorporates a list of U.S. patents and publications on the subject at column 2, lines 24 through 49.
It has long been known that recovery of petroleum using carbon dioxide could be greatly increased if the carbon dioxide were used in slug form and driven through the reservoir by an aqueous drive fluid, such as saline, plain, or carbonated water. A process using this technique is disclosed by Holm in U.S. Pat. No. 3,065,790. However, even alternate-injection, water-solvent processes using carbon dioxide as a solvent succeed in recovering only the petroleum in the reservoir contacted by the injected carbon dioxide. Large quantities of uncontacted petroleum are bypassed and left in the reservoir because an unfavorable mobility relationship between reservoir fluids and injected fluids causes the carbon dioxide to channel off into areas of high permeability. In the art of oil recovery the areal sweep efficiency of oil displacement is greatest when the viscosity of the displacing fluid is equal to or greater than the viscosity of the displaced oil and/or the permeability of the displacing fluid is less than or equal to that of the oil. Since carbon dioxide is less viscous and more mobile than most crude oils, it is not of itself a very efficient oil displacement agent.
The areal sweep efficiency of gas flooding, particularly of carbon-dioxide recovery, is increased by generating a foam in situ to block the highly permeable features of the underground formation. U.S. Pat. No. 3,342,256 to Bernard et al. (which is hereby incorporated by reference in its entirety) discloses alternative methods for generating foam in situ to prevent channeling of carbon dioxide into high permeability channels away from the zone to be treated. In one embodiment, a small amount of a surfactant or foaming agent is dissolved in the carbon dioxide, which is maintained as a dense fluid or liquid at pressures in excess of about 700 p.s.i.g. to ensure solubility. A subsequently injected drive medium, such as water, forces the carbon dioxide-surfactant mixture through the formation to a production well where production continues until the produced fluids exhibit an undesirably high water/oil ratio. Production is then terminated, and the formation is depressured to allow dissolved gases to come out of solution and form the foam. As the foam expands, it drives additional oil towards the producing well.
In an alternative embodiment, alternate slugs of carbon dioxide and the foaming agent, usually dissolved in an aqueous or hydrocarbon vehicle, are introduced into the reservoir. When a hydrocarbon vehicle is employed, the liquid light hydrocarbons will flash, producing a gas to generate foam in the areas of the reservoir of high pressure gradient, such as is found in high permeability channels. If a carbonated water vehicle is used to dissolve the foaming agent, upon encountering such areas of reduced pressure, the carbon dioxide will come out of solution and generate foam. The foam generated in situ by these released gases blocks the highly permeable strata and will prevent subsequently injected slugs of carbon dioxide from channeling into highly permeable zones.
Relying upon gases released in low pressure zones to generate the foam, however, presents certain disadvantages. When the foaming agent is dissolved directly into carbon dioxide or into carbonated water, a large portion of the gaseous carbon dioxide released in the low pressure zone does not go to generating foam, but is preferentially absorbed into the crude. And if the released carbon dioxide migrates into a high pressure region, solubility of carbon dioxide is increased and may approach miscibility at pressures in excess of about 700 p.s.i.g. These difficulties are not encountered if the foaming agent is dissolved in a hydrocarbon vehicle, but the cost of liquid hydrocarbons is generally prohibitive. Moreover, a hydrocarbon-soluble surface active agent generally foams the oil and restricts its movement through the reservoir. The upshot is that increasing the areal sweep efficiency of the recovery method by generating foam in situ is much more difficul and expensive in the reservoir than laboratory results might otherwise indicate.
An alternative method of plugging zones of high permeability within oil-bearing formations to control the flow of liquids through the reservoir utilizes formation of polymer plugs in situ. Typically various combinations are employed of a water-soluble polymer; a pH sensitive crosslinking agent reactive with the polymer, such as a polyvalent metal; and a pH controlling or buffering agent to control the time at which the crosslinking occurs. Typically, an acid or acid-releasing agent and/or an alkaline material are included in the polymer-containing solution as the pH-controlling or buffering agent.
For delayed crosslinking of polymer solutions within the reservoir, various techniques are known whereby the polymer solution is injected at a pH above that at which crosslinking typically occurs and the pH of the solution is reduced within the formation to trigger in situ gelation. For instance, the polymer-containing solution can be injected at an elevated pH, and then the reservoir rock is allowed to adsorb sufficient alkaline materials out of the injected solution to lower its pH below that at which crosslinking occurs. Or, a decrease in pH caused by connate waters from the reservoir diluting the polymer-containing solution can be relied upon to trigger crosslinking in situ. In some instances, a material that hydrolyzes within the reservoir is included in the polymer-containing aqueous solution so that crosslinking can be delayed until the polymer is emplaced into the formation. Nimerick in U.S. Pat. No. 3,740,360 discloses the latter method. Alternatively, the pH-controlling agent can be introduced into the reservoir in a separate slug immediately following a slug of the polymer solution to delay the crosslinking until the polymer solution has been placed into the reservoir. For example, U.S. Pat. Nos. 4,009,755 and 4,069,869 to Sandiford deal with forming plugs in wells wherein a gelatinous plug is formed in the reservoir by injecting (a) a water-soluble polymer, (b) a crosslinking material such as a compound of a multivalent metal and a reducing agent, such as a low-molecular weight water-soluble aldehyde, or a colloidal hydroxide of a multivalent cation, (c) an aqueous solution of an alkali metal silicate and (d) a gelling agent that reacts with the silicate to form a silicate-containing gelatinous plug.
Although gelatinous plugs typically are effective for controlling the flow of liquids, they are relatively ineffective for controlling the flow of gases. To restrict flow of a gas, such as gaseous carbon dioxide, through the higher permeability zones of a reservoir, an increased pressure drop such as is provided by a foam plug is normally required. But foams possess certain inherent disadvantages. Foams placed into the reservoir to block the flow of gases cannot withstand contact with water and other liquids, which dilute the concentration of the surface active agent and break down the bubbles in the foams. Also, foams tend to drain away naturally due to the action of gravity on the bubbles so that gases in the foam which are soluble in oil, such as carbon dioxide, are lost into solution.
Accordingly, while each of the foregoing methods has met with some success, the need exists for further developments in enhanced oil recovery. For example, a need exists for an improved method of blocking the highly permeable zones of producing formations during gas flooding, especially during carbon dioxide flooding, so that the flooding gas is not lost into the highly permeable, relatively oil-free zones of the reservoir but contacts a larger cross-section of the oil-bearing strata. What is particularly needed is a method for creating a gelatinous foam in situ by injecting gases comprising an acid gas such as carbon dioxide in conjunction with an aqueous solution of a water-soluble surface active agent, a water-soluble polymer, a crosslinking agent for the polymer, and an alkaline material capable of delaying cross-linking of the polymer until it has been placed into the reservoir. The gelatinous foam generated in situ by this process blocks the highly permeable zones into which the flooding gases tend to finger and diverts subsequently injected gases and drive fluids into the less permeable, oil-containing zones, thereby substantially increasing the efficiency of oil recovery. Moreover, the stiff foam films of a gelatinous foam reduce the natural tendency of the foam to collapse by absorption of the soluble gas into the oil.